Aqueous based well treatment fluids are commonly used in drilling, stimulation, completion and workover operations of subterranean formations. Treatment designs typically mandate such fluids to exhibit a certain level of viscosity. Viscosifying polymers, such as polysaccharides, are often used in such fluids therefore to provide the requisite viscosity. For instance, the viscosifying polymer often provides the requisite level of viscosity needed to prevent the loss of well treatment fluids into the formation. In drilling fluids, such polymers serve to suspend solids and assist in floating debris out of the wellbore.
Unfortunately, the thermal stability of aqueous well treatment fluids containing a viscosifying polymer is often compromised as such fluids pass down the wellbore and are exposed to increasing temperatures. Temperatures in subterranean formations generally rise about 1° C. per hundred feet of depth. It is important, therefore, that such aqueous fluids are thermally stable at elevated temperatures.
Thermal instability typically causes degradation of the polymeric viscosifying agent which causes the viscosity of the well treatment fluid to decrease. A decrease in viscosity of a well treatment fluid often has detrimental effects on the wellbore treatment operation. For instance, a decrease in viscosity of drilling fluid often results in loss of suspension of drill cuttings which, in turns, results in the inability of such cuttings to float out of the wellbore. In addition, during drilling operations, degradation of the polymeric viscosifying agent may cause the drill string to bind in the wellbore and induce formation damage.
Ancillary to the need for maintaining viscosity, the well treatment fluid must have a sufficiently high density for the well treatment fluid to be operable at high temperatures and be able to withstand relatively high fluid pressures downhole.
High density brines have been found to have particular applicability in deep wells, such as those that descend 15,000 to 30,000 feet (4,500 to 10,000 meters) or more below the earth's surface, where it is most desirous to reduce pump pressure. Such brines have been found to be capable of maintaining the requisite lubricity and viscosity of the well treatment fluid under extreme shear, pressure and temperature variances encountered during operations of deep wells.
Exemplary of high density brines are sodium chloride, potassium chloride, calcium chloride, sodium bromide, calcium bromide, zinc bromide, potassium formate, cesium formate and sodium formate brines. While nitrate brines have been suggested for use in well treatment fluids such as completion and packer fluids, efforts to use such brines for such applications were abandoned, however, in the late 1950s after it was discovered that they contributed to stress corrosion cracking of carbon steels. Intergranular corrosion was further found to be caused when mixing chloride and nitrates. See, for instance, Hudgins and Greathouse, “Corrosion Problems in the Use of Dense Salt Solutions”, Corrosion, November, 1960, wherein it was reported the corrosion process could be inhibited by saturating the brine with lime or by keeping the pH above about 9. However, entrained carbon dioxide from the producing well reduced the pH of the brine. The use of such brines was, therefore, severely hindered.
One area of particular applicability for high density brines is in production stimulation treatments of deep wells wherein the brine fluid is used as a fracturing fluid. Pumping through work strings in such wells typically requires tremendous pressures. It is not uncommon that the amount of horsepower required for a job cannot be provided in light of the extremely high friction pressures generated during the pumping stage. In such instances, the hydrostatic pressure of a high density fluid counterbalances the pressure exerted by the fluid in the strata. In addition to having high density, the fracturing fluid must be highly viscous in order for it to suspend proppant. It is the proppant which is deposited into the created fractures and which prevents the formed fractures from closing after the completion of pumping. Conductive channels are thereby formed through which produced fluids may flow to the wellbore.
Unfortunately, under the severe wellbore conditions encountered in the treatment of deep wells, many viscosifying agents, particularly polysaccharides, degrade and depolymerize, thus losing their effectiveness.
As interest in treatment operations at deeper depths increases, there is a continual need for alternative well treatment fluids having enhanced thermal stability and which maintain their density at downhole conditions at least for two to three hours. It is further important that such alternative well treatment fluids be capable of reducing the requisite pump pressure generated during the well treatment operation.